Solid particle erosion indicator module for a valve and actuator monitoring system

ABSTRACT

The present application provides a method of evaluating valve conditions in a turbine by a data acquisition system. The method may include the steps of receiving a number of operating parameters from a number of sensors, wherein the operating parameters may include steam temperatures determined over time and steam pressure, determining a steam chemistry, a throttling history, and a piping material, determining a probability of valve erosion based upon the steam temperatures determined over time, the steam chemistry, the throttling history, and the piping material, and altering one or more of the operating parameters and/or initiating repair procedures based upon the determined probability.

TECHNICAL FIELD

The present application and resultant patent relate generally tomonitoring and control systems for steam turbines and other types ofturbomachinery and more particularly relate to a valve and actuatormonitoring system for steam turbines and the like that providescontinuous component and system status information, warnings, andcorrections.

BACKGROUND OF THE INVENTION

A steam turbine converts the kinetic or thermal energy of pressurizedsteam into useful mechanical work. Generally described, the steam iscreated in a steam generator or a boiler, passes through control valvesand stop valves into the sections, and drives a rotor assembly. Therotor assembly then in turn may drive a generator to produce electricalenergy and the like. The control valves and the stop valves control theoperation of the steam turbine by controlling the flow of the steam intothe sections. A control valve typically controls or regulates thevolumetric flow and/or the pressure of the steam entering into thesections during normal operation levels. A stop valve is typically asafety valve. The stop valve is typically held open during normaloperation and closed when immediate shutdown is necessary. In someapplications, the control valve and the stop valve may be integratedinto a single unit.

Due to market demands, steam turbines may be required to operate withincreased cycling and longer inspection intervals. In order to obtainsignificant information about the condition of the steam turbinecomponents, such as the control valves and the stop valves, conditionmonitoring systems may be used. Such monitoring systems, however, may belimited in scope in that certain types of component wear or damage mayonly be apparent via visual inspection during a system shutdown. Suchoutage costs and time may be significant.

SUMMARY OF THE INVENTION

The present application and the resultant patent provide a method ofevaluating valve conditions in a turbine by a data acquisition system.The method may include the steps of receiving a number of operatingparameters from a number of sensors, wherein the operating parametersmay include steam temperatures determined over time and steam pressure,determining a steam chemistry, a throttling history, and a pipingmaterial, determining a probability of valve erosion based upon thesteam temperatures determined over time, the steam chemistry, thethrottling history, and the piping material, and altering one or more ofthe operating parameters and/or initiating repair procedures based uponthe determined probability.

The present application and the resultant patent further provide aturbine system. The turbine system may include a number of valves, anumber of sensors capable of receiving turbine and valve operatingparameters, and a data acquisition system, including a processor incommunication with the sensors. The data acquisition system is operableto perform the following operations: receiving the turbine and valveoperating parameters from the sensors, wherein the turbine and valveoperating parameters may include steam temperatures determined overtime, determining a steam chemistry, a throttling history, and a pipingmaterial, and determining a probability of valve erosion based upon thesteam temperatures, the steam chemistry, the throttling history, and thepiping material.

The present application and the resultant patent further provide amethod of evaluating valve conditions in a turbine by a data acquisitionsystem. The method may include the steps of receiving a number ofoperating parameters from a number of sensors, wherein the operatingparameters may include a steam temperature and a time of operation,determining a steam chemistry and a piping material, determining aprobability of valve scaling based upon the steam temperature, the timeof operation, the steam chemistry, and the piping material, and alteringone or more of the operating parameters and/or initiating repairprocedures based upon the determined probability.

These and other features and improvements of the present application andresultant patent will become apparent to one of ordinary skill in theart upon review of the following detailed description when taken inconjunction with the several drawings and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a steam turbine system as may bedescribed herein.

FIG. 2 is a partial perspective view of a combined stop valve andcontrol valve that may be used with the steam turbine system of FIG. 1.

FIG. 3 is a partial cross-sectional view of the combined stop valve andcontrol valve of FIG. 2.

FIG. 4 is a schematic diagram of a distributed control system for usewith the combined stop valve and control valve of FIG. 2.

FIG. 5 is a schematic diagram of a Valve and Actuator Monitoring System(“VAMS”) as may be described herein.

FIG. 6 is a flow chart of exemplary method steps in an Advanced Start-upCounter Module for use with VAMS of FIG. 5.

FIG. 7 is a flow chart of exemplary method steps in an AdvancedThrottling Time Counter Module for use with VAMS of FIG. 5.

FIG. 8 is a flow chart of exemplary method steps in a Guiding ConditionAssessment Module for use with VAMS of FIG. 5.

FIG. 9 is a flow chart of exemplary method steps in a Valve Stroke andSpindle Way Counter Module for use with VAMS of FIG. 5.

FIG. 10 is a flow chart of exemplary method steps in a Tightness TestEvaluation Module for use with VAMS of FIG. 5.

FIG. 11 is a flow chart of exemplary method steps in an AdvancedTightness Test Evaluation Module for use with VAMS of FIG. 5.

FIG. 12 is a flow chart of exemplary method steps in a Spindle VibrationEvaluation Module for use with VAMS of FIG. 5.

FIG. 13 is a flow chart of exemplary method steps in an InsulationQuality Indicator Module for use with VAMS of FIG. 5.

FIG. 14 is a flow chart of exemplary method steps in a Solid ParticleErosion Indicator Module for use with VAMS of FIG. 5.

FIG. 15 is a flow chart of exemplary method steps in a Scaling IndicatorModule for use with VAMS of FIG. 5.

FIG. 16 is a flow chart of exemplary method steps in a Flexible ServiceCounter Module for use with VAMS of FIG. 5.

DETAILED DESCRIPTION

Referring now to the drawings, in which like numerals refer to likeelements throughout the several views, FIG. 1 is a schematic diagram ofa steam turbine system 100 as may be described herein. Generallydescribed, the steam turbine system 100 may include a high pressuresection 110, an intermediate pressure section 120, and a low pressuresection 130. The high pressure section 110, the intermediate pressuresection 120, and the low pressure section 130 may be positioned on andmay drive a rotor shaft 140. The rotor shaft 140 also may drive agenerator 150 for the production of electrical power or for other typesof useful work. The steam turbine system 100 may have any suitable size,shape, configuration, or capacity.

A boiler 160 and the like may produce a flow of steam 170. The boiler160 and the flow of steam 170 may be in communication with the highpressure section 110 via a high pressure line 180. The steam 170 maydrive the high pressure section 110 and exit the high pressure section110 via a cold reheat line 190. The cold reheat line 190 may be incommunication with a reheater 200 (i.e., the boiler 160 or partthereof). The reheater 200 may reheat the flow of steam 170. Thereheater 200 and the flow of steam 170 may be in communication with theintermediate pressure section 120 via an intermediate pressure line 210.The flow of steam 170 may drive the intermediate pressure section 120and may exit the intermediate pressure section 120 via a low pressureline 220. The flow of steam 170 then may drive the low pressure section130 and may exit via a condenser line 230 to a condenser 240. The nowcondensed flow of steam 170 then may be returned to the boiler 160 ordirected elsewhere. Other types of cycles and other types of componentsmay be used herein.

The steam turbine system 100 may include a number of steam valves 260.The steam valves 260 may include a stop valve 270 and a control valve280. Specifically, a high pressure stop valve and control valve 290 maybe positioned on the high pressure line 180 while an intermediatepressure stop and control valve 300 may be positioned on theintermediate pressure line 210. Other types of valves and otherlocations may be used herein. As is shown in FIG. 2 and FIG. 3, the stopand control valves 290, 300 may include the stop valve 270 and thecontrol valve 280 positioned within a common casing 310. The casing 310may include one or more layers of insulation 315. The stop valve 270 mayinclude a stop valve closing member 320. The stop valve closing member320 may be driven by a stop valve spindle 330. The stop valve spindle330 may in turn be driven by a stop valve actuator 340. Similarly, thecontrol valve 280 may include a control valve closing member 350, acontrol valve spindle 360, and a control valve actuator 370. The steamvalves 260 described herein are for the purpose of example only. Manyother types of steam valves 270 and components thereof may be usedherein in any suitable size, shape, or configuration.

The steam turbine system 100 may include a number of sensors 380. Thesensors 380 may be of conventional design and may gather data on anytype of operational parameter and the like. By way of the example only,the sensors 380 may include a speed sensor 390. The speed sensor 390 maybe positioned about the rotor shaft 140 so as to determine the speed andacceleration thereof. The sensors 380 may include a number of metaltemperature sensors such as a high pressure section metal temperaturesensor 400 and an intermediate pressure section metal temperature sensor410. The metal temperature sensors 400, 410 may be positioned about therotor shaft 140 in the high pressure section 110 and the intermediatepressure section 120. The sensors 380 also may include a number of steamtemperature sensors. The steam temperature sensors may include a highpressure section inlet temperature sensor 420 and a high pressuresection outlet temperature sensor 430 positioned about the high pressuresection 110 and an intermediate pressure section inlet temperaturesensor 440 positioned about the intermediate pressure section 120. Thesteam temperature sensors also may include a high pressure valvetemperature sensor 450 positioned about the high pressure stop andcontrol valve 290 and an intermediate pressure valve temperature sensor460 positioned about the intermediate pressure stop and control valve300. The sensors 380 may include a number of steam pressure sensors. Thesteam pressure sensors may include a high pressure section exhaustpressure sensor 470 positioned about the high pressure section 110, ahigh pressure valve pressure sensor 480 positioned downstream of thehigh pressure stop and control valve 290, and an intermediate pressurevalve pressure sensor 490 positioned downstream of the intermediatepressure stop and control valve 300. The sensors 380 also may include anumber of mass flow sensors. The mass flow rate sensors may include ahigh pressure valve flow rate sensor 500 positioned about the highpressure stop and control valve 290 and an intermediate pressure valveflow rate sensor 510 positioned about the intermediate pressure stop andcontrol valve 300.

The stop and control valves 290, 300 themselves also may include anumber of sensors. These valves may include a stop valve inner casingtemperature sensor 520 at an inner wall, a stop valve outer casingtemperature sensor 530 at an outer wall, a control valve inner casingtemperature sensor 540 at an inner wall, and a control valve outercasing temperature sensor 550 at an outer wall. The stop valve 270 mayhave an inlet pressure sensor 5600. A middle pressure sensor 575 may bepositioned between the stop valve 270 and the control valve 280. Thecontrol valve spindle 360 may include a vibration sensor 580 while theactuators 340, 370 may have a position sensor 590 positioned on theshafts therein as well as a hydraulic pressure valve 595. The sensors380 described herein are for the purpose of example only. Many other anddifferent types of sensors also may be used herein.

FIG. 4 shows an example of an existing valve control system 600. Thevalve control system 600 may be used with any of the steam valves 260described above and the like. As shown above, the steam valve 260 may beoperated via an actuator 610. The actuator 610 may be of conventionaldesign. Specifically, the steam valve 260 may be controlled via anelectro-hydraulic converter 620. The electro-hydraulic converter 620 mayinclude a converter valve 630 and a valve controller 640. Theelectro-hydraulic converter 620 converts an electric control signal intoa corresponding hydraulic pressure for the actuator 610. Theelectro-hydraulic converter 620 may be of conventional design. The valvecontroller 640 may be in communication with installation andcommissioning tool 650. The installation and commissioning tool 650 maybe a conventional microprocessor and the like. The installationcommissioning tool 650 may be used for valve set up and for periodicmeasurements. The installation and commissioning tool 650 may beconnected to the electro-hydraulic converter 620 on request. Any numberof the steam valves 260 may be controlled via a turbine governor 660 incommunication with a distributed control system 670. The current valvecontrol system 600 does not provide online monitoring or integrationinto existing monitoring systems. Input from the various sensors 380 maybe in communication with the turbine governor 660 and/or the distributedcontrol system 670 as may be required. Other components and otherconfigurations may be used herein.

FIG. 5 shows an example of a valve and actuator monitoring system 700 asmay be described herein (hereinafter “VAMS 700”). VAMS 700 assess thecondition of the steam valves 260 based on continuous monitoring. VAMS700 may provide real time monitoring of the steam valves 260 forcondition assessment, predictive maintenance, correction, ordering spareparts, and the like. VAMS 700 may include a data acquisition system 710.Elements of the data acquisition system 710 may be used to acquireoperational data of the steam valves 260 and control operation thereofand operational data of the steam turbine and the steam plant.

The data acquisition system 710 may include a historian 720. Thehistorian 720 may be software and may or may not include databasefunctions. The historian 720 interfaces with programmed logic viacalculators and runs on data available therein. The historian 720 maystore data received from the sensors 380 and the like and processeddata. The historian 720 may be able to record non-scalar data as well asscalar data. (The valve controller 640 and the like may provide highspeed recording for events with data output in a non-scalar format.)Other types of databases and platforms may be used herein. The dataacquisition system 710 may import programmed logic implemented bysoftware, hardware, firmware, or any combination thereof. The historians720 may be cascaded such that one historian 720 may run on a server andcollect data from a number of VAMS 700. Likewise, multiple dataacquisition systems 710 may be used such that different featuresdescribed herein may be executed on one or more of such differentsystems.

The data acquisition system 710 also may include a processor 730. Theprocessor 730 may provide data filtering and processing. The processor730 may utilize an operating system to execute program logic and, indoing so, also may utilize the measured data found on the historian 720.The processor 730 may include a calculator for computations. Thecalculator may be a freely programmable computation engine and can bewritten for the historian 720. The program languages may include Python,C/C++, and the like. The data acquisition system 710 receives availabledata and makes computation as to the assessment thereof.

Users may interface with the data acquisition system 710 via a graphicaluser interface 740. The graphical user interface 740 may include adisplay, keyboard, keypad, a mouse, control panel, a touch screendisplay, a microphone, and the like so as to facilitate userinteraction. Specifically, the graphical user interface 740 may supporta work station 750 wherein the data acquisition system 710 may providetrends, alarms, events, and the like. Data output by the dataacquisition system 710 may be available to customers via the graphicaluser interface 740. The graphical user interface 740 may be incommunication with the historian 720 and the processor 730. Allavailable data such as measurements, processed data, and the like thuswill be easily accessible. The data acquisition system 710 may be incommunication with the valves 260 and the sensors 380 and the othercomponents herein via one or more data busses 760. VAMS 700 may operateunattended, without user interaction. Other components and otherconfigurations may be used herein.

The data acquisition system 710 may be positioned locally at the steamturbine system 100 and/or remotely at a customer's location. A number ofdata acquisition systems 710 may be in communication with a clientacquisition system 745. The client acquisition system 745 may have asimilar configuration and components. Moreover, the historian 720 at theclient acquisition system 745 at the customer site may collect dataacross multiple steam valves 260. The data acquisition systems 710and/or the client acquisition systems 745 also may be in communicationwith a central data center 770. The central data center 770 may be incommunication with the data acquisition systems 710 and or the clientacquisition systems 745 via a virtual private network or the Internet780 via a data collection in transmission tool 765, a secure filetransfer, and the like. Further processing may be performed at thecentral data center 770. Other components and other configurations maybe used herein.

References are made to block diagrams of systems, methods, apparatuses,and computer program products according to example embodiments. It willbe understood that at least some of the blocks of the block diagrams,and combinations of blocks in the block diagrams, may be implemented atleast partially by computer program instructions. As described above,these computer program instructions may be loaded onto a general purposecomputer, a special purpose computer, a special purpose hardware-basedcomputer, or other type of programmable data processing apparatus toproduce a machine, such that the instructions that execute on thecomputer or other programmable data processing apparatus create meansfor implementing the functionality of at least some of the blocks of theblock diagrams, or combinations of blocks in the block diagramsdiscussed below.

These computer program instructions also may be stored in anon-transitory, computer-readable memory that can direct the computer orother programmable data processing apparatus to function in a particularmanner, such that the instructions stored in the computer-readablememory produce an article of manufacture including instruction meansthat implement the functions specified in the block or blocks. Thecomputer program instructions also may be loaded onto a computer orother programmable data processing apparatus to create a series ofoperational steps to be performed on the computer or other programmableapparatus to produce a computer implemented process such that theinstructions that are executed on the computer or other programmableapparatus provide steps for implementing the functions specified in theblock or blocks.

One or more components of the systems and one or more elements of themethods described herein may be implemented through an applicationprogram running on an operating system of a computer. They also may bepracticed with other computer system configurations, including hand helddevices, multiprocessor systems, microprocessor-based or programmableconsumer electronics, mini-computers, mainframe computers, and the like.Application programs that are components of the systems and methodsdescribed herein may include routines, programs, components, datastructures, and so forth that implement certain abstract data types andperform certain tasks or actions. In a distributed computingenvironment, the application program (in whole or in part) may belocated in local memory or in other storage. In addition, oralternatively, the application program (in whole or in part) may belocated in remote memory or in storage to allow for circumstances wheretasks are performed by remote processing devices linked through acommunications network.

VAMS 700 thus may provide real time monitoring of the various valves andactuators. Specifically, VAMS 700 thus may provide real time statusinformation, messages, warnings, and lifetime consumption information soas to provide determinations and predictions by comparing the actualdata to design data. The following modules describe different types ofinspection and monitoring techniques and methods that may be usedherein. Many other and different modules and methods may be used herein,separately or together.

FIG. 6 shows a flow chart of example method steps for use in an AdvancedStart-up Counter Module 800 as may be described herein. A conventionalsteam turbine generally counts the number of cold starts, warm starts,and hot starts. The Advanced Start-up Counter module 800 gathers furtherand more powerful information so as to provide estimations on low cyclefatigue damage. Specifically, the Advanced Start-up Counter Module 800counts the number of starts and allocates to each start-up informationconcerning the shut-off period, the shut-down temperature drop, thestart-up time, and the like. The Advanced Start-up Counter Module 800creates a list of the start-ups and further information and thendetermines a severity indicator of the extent of possible fatiguedamage.

By way of example, VAMS 700 gathers operating turbine and valveparameters from a number of sensors 380 and determines a number ofoperating conditions. Specifically at step 810, VAMS 700 determines astand-still time from the last shut-down to the current start-up.Shut-down and start-up status may be determined by the position of thestop valves 270 via the position sensor 590 or from a signal of theturbine controller or from any other source. The valves and theactuators may be permanently monitored herein. At step 820, VAMS 700 maydetermine the shut-down temperature drop, i.e., the temperature decreaseduring the shut-down period. Alternatively or additionally, atemperature transient during the shut-down period may be determined. Atstep 830, VAMS 700 may determine if the start-up is a “cold start”, a“warm start”, or a “hot start” and/or VAMS 700 may determine the valvecasing temperature via one of the metal temperature sensors 400, 410.The number and nature of the starts may be displayed and provided to theoperator. The type of start-up (cold start, warm start, or hot start,for example) also may be read from signals from the turbine controller.

At step 840, VAMS 700 may determine the times to X % load of the steamturbine. The X % load may be set at 10% of load, 20% of load, . . . ,100% of load, or any percentage in between. At step 860, VAMS 700 maychart and display the time to X % load against the stand-still time. Thechart may show all starts in the life of a particular valve or theturbine in general. Design data also may be used so as to compare designtimes to actual times.

At step 870, VAMS 700 may determine a number of ratios of actual datacompared to design data. This may include a time ratio of a designstart-up time to a time to X % load, a start-up temperature ratio of astart-up temperature transient to a design temperature transient, and ashut-down temperature ratio of the shut-down temperature drop ortransient to a design temperature drop or transient. At step 880, VAMS700 may determine a severity factor based on the average of the timeratio, the start-up temperature ratio, and/or the shut-down temperatureratio and/or a severity factor based on the maximum of these ratios.Alternatively, a severity factor based on the average of all the timeratios of all starts since the beginning of turbine operation or sincethe last valve inspection or since any other time point may bedetermined by the VAMS 700. In the same way, a severity factor based onthe average of all of the start-up temperature ratios of all starts anda severity factor based on the average of all of the shut-downtemperature ratios of all shut-downs may be determined.

The severity factors also may be used to determine a factorized sum ofstarts. Instead of counting x cold starts, y warm starts, and z hotstarts, the factorized sum of starts may be a sum of the characteristicseverity factors of all starts. A characteristic severity factor may bea value, characterizing the severity of one specific start. This may bedetermined by building the product of the time ratio, the start-uptemperature ratio, and the shut-down temperature ratio or by buildingthe product of these ratios, whereby each of the ratios is weighted witha weighting factor. Instead of the three values x, y, z for the numberof starts, the factorized sum of the starts may be one value, which is abetter indicator of the fatigue damage, caused by all the start-ups andshut-downs in the time period of interest.

At step 885, VAMS 700 may determine if any one of these severity factorsis more than 1.0. If so, VAMS 700 may issue a fatigue warning at step890. Such a fatigue warning may include not only displaying theinformation to the operator but also changing one or more of theoperating parameter or operating conditions and/or initiating repairprocedures and/or initiating exchange of valve parts. These operatingparameters may include times, temperatures, and the like. If all of theseverity factors are less than 1.0, VAMS 700 may indicate normaloperation at step 895. In any event, current fatigue status will bedisplayed and available to the operator.

Shorter actual start-up times may mean higher severity. Likewise, higheractual temperature transients may mean higher severity. The AdvancedStart-up Counter Module 800 thus provides the operator with a detailedoverview of the start-up history and indicates in a simple way thepossible low cycle fatigue damage. This information may be updated foreach start. The Advanced Start-up Counter Module 800 thus may provide amore accurate description of possible fatigue damage as compared toknown counters without the need for visual inspection and downtime. TheAdvanced Start-up Counter Module 800 thus can support the decision, whena valve inspection shall be performed, e.g., by defining an upper limitfor the factorized sum of starts in between two inspections.

FIG. 7 shows example method steps in an Advanced Throttling Time CounterModule 900 as may be described herein. The Advanced Throttling TimeCounter Module 900 indicates whether a given valve is operating in heavythrottling conditions. Specifically, when the valve bell and the like isin a certain position range and when the pressure ratio over the valveis in a certain range, then the valve may be vibrating strongly due toexcitation under unstable steam flow. Such vibration may lead toincreased wear and/or damage of the valve if this vibration occurs overa longer period of time.

By way of example, at step 910 VAMS 700 may determine different types ofturbine and valve operating parameters. These operating parameter mayinclude the pressure from the valve inlet pressure sensor 560 and thepressure drop over the valve from the valve inlet pressure sensor 560and the high pressure valve pressure sensor 480 at the high pressuresection 110, the intermediate pressure valve pressure sensor 490 at theintermediate pressure section 120, the position of the spindle via thespindle position sensor 590, the mass flow rate via the flow ratesensors 500, 510, and the like. The valves and the actuators may bepermanently monitored. At step 920, VAMS 700 may determine if a valve isin a vibration state, i.e., if certain parameters exceed predeterminedvalues. For example, whether the valve bell is in a certain positionrange and if the pressure ratio (i.e., pressure after the control valveseat divided by the pressure before the control valve seat) is in acertain range. The position and the pressure ratio ranges with highvibrations are determined experimentally or theoretical analysis, e.g.,3D flow analysis. At step 930, VAMS 700 may determine the time that thevalve has been operated in the vibration state. At step 940, VAMS 700may determine a severity factor based on the ratio of the time in thevibration state to the total operating time and on the ratio of theallowable vibration time to the total operating time. The allowablevibration time may be received by experience. At step 950, VAMS 700 maydetermine if the severity factor is more than 1.0. A ratio greater than1.0 may indicate unfavorable throttling operation. At step 960, VAMS 700may issue a throttling warning if the ratio is greater than 1.0. Such athrottling warning may include not only displaying the information tothe operator but also changing one or more of the operating parameter oroperating conditions and/or initiating repair procedures and/orinitiating an exchange of valve parts. The operating parameters mayinclude changing pressure, temperature, spindle position, mass flowrate, and the like. If ratio is less than 1.0, VAMS 700 may indicatenormal operation at step 970. In any event, current vibration statuswill be displayed to the operator. VAMS 700 also may provide statisticson how long the valve was operated at each stroke, accumulated vibrationtime. Excessive or unusual vibration also may be determined andreported.

The Advanced Throttling Time Counter 900 thus provides information onthe likely wear and erosion condition of a given valve. The operator maybetter manage spare parts in that the operator only needs to order partswhen needed or in advance of a planned inspection. Unnecessary spareparts do not need to be kept in stock. The Advanced Throttling TimeCounter Module 900 thus gives the operator an overview of theaccumulative vibration history of the valve. This history provides anindication for the wear of the guides and the erosion of the valveseats. The Advanced Throttling Time Counter Module 900 thus may providea more accurate description of possible wear damage without the need forvisual inspection and downtime.

FIG. 8 is a flow chart showing exemplary method steps in a GuideCondition Assessment Module 1000 as may be described herein. The GuideCondition Assessment Module 1000 may measure and evaluate the frictionbehavior of the spindles in the steam valves 260. The resulting frictioncharacteristics may be compared with previous measurements and a trendof the friction characteristics may be assessed. Such an assessment isin contrast to current inspection methods requiring the disassembly ofthe valves. These current methods may result in a leaking valve inbetween inspection intervals that may present an operational risk aswell as health and safety issues.

Generally described, the spindle within each steam valve 260 may beguided within guide bushes or other guiding elements (such as bores invalves) and may be tightened to the outside, e.g., with graphitepackings. Due to valve vibrations, ageing, corrosion, oxidation, wear,changing of roughness, erosion, particles in the steam and followingdeposits on the sliding faces, as well as changes to clearance due todeformation, the sliding behavior of the spindle at the guide elementsand the spindle seals may change over time. Such changes may result inthe spindle beginning to stick such that the valve may not be able toclose properly or may result in loosening the pre-tension in thegraphite seals. In order to assess the condition of the steam valves 230at step 1010, VAMS 700 may obtain operational parameters such as theposition of the spindle via the position sensor 590, steam pressure fromthe pressure sensors 480, 490, 560, as well as the hydraulic pressure ofthe high pressure oil in the actuators 340, 370 via the hydraulicpressure sensor 595. Other types of parameters also may be consideredherein. The valves and the actuators may be permanently monitored. Atstep 1020, VAMS 700 may generate a friction hysteresis curve, i.e., thehydraulic pressure dependence of the spindle position during movement ofthe spindle first in closing and then in the opening position. Thedifference in the hydraulic pressure in the opening and the closingdirections shows the static and sliding friction (static friction, whenthe spindle is stopping before the movement starts, e.g., at the turningpoint of the spindle movements; sliding friction, at those spindlepositions, where the spindle is not stopping.) At step 1030, VAMS 700may determine a friction characteristic. The friction characteristic mayinclude the calculated static friction at the top and bottom turningpoint and the sliding friction with maximum, average, and minimum valuesand curves of static and sliding friction over the spindle way in bothdirections. Other types of friction characteristics may be evaluatedherein. At step 1040, VAMS 700 may compare the determined frictioncharacteristics, i.e., the friction values as described above, tofriction characteristics from previous stroke tests. At step 1050, VAMS700 may determine whether the friction characteristics are increasingand/or whether the determined friction characteristic exceeds apredetermined value. If so, a valve failure warning may be issued atstep 1060. Such a valve failure warning may include not only displayingthe information to the operator but also taking the valve off line,changing one or more of the operating parameters or operatingconditions, and/or initiating repair procedures. The operatingparameters may include hydraulic and steam pressure, spindle position,steam and metal temperatures, and the like. If not, normal operation maybe indicated at step 1070.

The Guide Condition Assessment module 1000 thus may provide an operatorwith an early warning that a valve may be sticking. Such an earlywarning may allow the operator to re-tighten the spindle seals of thevalve and/or order spare parts and/or plan for remachining of the guidesto ensure correct clearances. Previously, an improperly working sealcould only be detected during inspection or via the leakage duringoperation. The Guiding Condition Assessment Module 1000 thus insuresthat the valves provide sufficient steam tightness toward theenvironment and gives a pre-warning, when the valve guides are gettingworse, before the event of a sticking valve occurs. The Guide ConditionAssessment Module 1000 thus may provide a more accurate description ofpossible guide and seal damage without the need for visual inspectionand downtime.

FIG. 9 is a flow chart showing exemplary method steps in a Valve Strokeand Spindle Way Counter Module 1100 as may be described herein. The wearof the internal spindle guide is influenced by the number of valvestrokes and the covered distance of the valve head. The more strokes andthe longer the covered distance, the more wear may be expected.Previously, the condition of the guides and the seals of the valvespindle could only be discovered by disassembling the valve.

The Valve Stroke and Spindle Way Counter Module 1100 thus counts thenumber of strokes (stroke counter) and counts the covered distance (waycounter). Specifically, VAMS 700 at step 1110 obtains the time dependentspindle position from the position sensor 590 and counts the strokes andthe covered distance. The valves and the actuators may be permanentlymonitored. At step 1120, VAMS 700 may classify the strokes according tostroke value, i.e., VAMS 700 may sort the strokes according to size(linear distributed ranges or sorted in geometrical series) and the meanspindle position. Further, the time that the spindle stays in a certainposition also may be counted. The strokes may be considered small,medium, large or otherwise. When the valve is controlling, the spindleusually performs permanent small strokes. Such small strokes may befiltered out or removed from the overall statistics. The stroke valuesmay be determined via a rainflow method, a range mean method, and thelike. The rainflow method may be used in an analysis of spindle movementdata in order to reduce a spectrum of varying spindle movement into aset of simple strokes. Specifically, the rainflow method is a method forcounting cycles from a time history. Other types of cycle countingmethods and spindle movement analysis may be used herein.

At step 1130, VAMS 700 may evaluate the overall spindle movementhistory. The movement history may be shown as scalar values, matrices,or diagrams. At step 1140, VAMS 700 may compare the movement historywith known allowable values. Based upon this comparison, VAMS 700 mayprovide an estimate of the remaining time to guide replacement at step1150. Depending upon the comparison, VAMS 700 also may take the valveoff line, change one or more of the operating parameter or operatingconditions, and/or initiate repair procedures, e.g., for repairing thespindle guides and/or the spindle seals. The estimates may be shown tothe plant operator on a monitor or otherwise reported.

The Valve Stroke and Spindle Way Counter Module 1100 thus gives theplant operator permanently an overview of the current status of themovement history. Such movement history provides an indication of thewear of the guides and the spindle seals and whether the guides and theseals should be replaced now, at the next inspection, or otherwise. Theplant operator may consider this information for inspection planning andfor ordering spare parts. The valve parts may include worn guides, wornspindle, worn graphite packaging, and the like. Overall informationconcerning lifetime consumption and residual life also may be provided.The Valve Stroke and Spindle Way Counter Module 1100 thus may provide amore accurate description of possible guide wear without the need forvisual inspection and downtime.

FIG. 10 is a flow chart of exemplary steps in a Tightness TestEvaluation Module 1200 as may be described herein. The Tightness TestEvaluation Module 1200 may give the plant operator an overview of thecurrent status of the tightness of the valves in comparison to the pastmeasurements. Specifically, the Tightness Test Evaluation Module 1200may provide an indication of the status of the piston rings and anyerosion at the valve seat to determine whether the piston rings, thebell, the diffuser, and the like should be replaced now, at the nextinspection, or otherwise. Further, the Tightness Test Evaluation Module1200 compares the tightness tests of the turbine throughout the overalloperation history and determines whether there is a trend of increasingvalve leakage and hence valve damage.

By way of example, VAMS 700 may obtain turbine and valve operatingparameters such as rotor speed from the rotor speed sensor 390, valveposition from the position sensor 590, steam pressure from the pressuresensors 470, 480, 490, and temperature from the temperature sensors 420,430, 440, 450, 460. The valves and the actuators may be permanentlymonitored. At step 1210, VAMS 700 may begin the tightness test. Thebeginning of the test may coincide with the opening of the stop valve270. At step 1230, the rotor acceleration directly after opening thestop valve 270 may be measured. At step 1240, the test may be ended andthe rotor speed may be determined at the end of the test at step 1250.At step 1260, VAMS 700 may compare the determined rotor acceleration andthe determined rotor speed to allowable values. At step 1270, VAMS 700may provide the operator with a leakage warning if the determined rotoracceleration and/or the determined rotor speed exceed allowable values.Specifically, the Tightness Test Evaluation Module 1200 determineswhether the steam flow through the valve at a closed position is belowthe allowable limit. The allowable limit may be defined by the increasein the rotor speed and/or by the increase of the rotor acceleration.Such a valve failure warning may include not only displaying theinformation to the operator but also taking the valve off line, changingone or more of the operating parameter or operating conditions, and/orinitiating repair procedures. The operating parameters may includespeed, pressure, temperature, spindle position, and the like.

After a predetermined interval, the tightness test may be repeated atstep 1280. At step 1290, VAMS 700 may compare the results of repeatedtightness tests (rotor speed at the end of the test, acceleration at thebeginning of the test) and different kinds of trend lines may becalculated, i.e., straight and exponential. At step 1295, VAMS 700 maycalculate a predicted time to an unacceptable leakage based on thetrendlines. The plant operator may consider this prediction forinspection planning and in ordering spare parts. The Tightness TestEvaluation Module 1200 thus gives the plant operator an overview of thecurrent status of the tightness of the valves in comparison to the past.The plant operator thus may have warning about insufficient tightnessbefore reaching critical values. The Tightness Test Evaluation Module1200 thus may provide a more accurate description of valve tightnesswithout the need for visual inspection and downtime.

FIG. 11 is a flow chart showing example method steps in an AdvancedTightness Test Evaluation Module 1300 as may be described herein.Similar to the Tightness Test Evaluation Module 1200 described above,the Advanced Tightness Test Evaluation Module 1300 is a furtherenhancement using pressure decay and stable pressure values as analternative and/or as an additional indicator for valve tightness andhealth. Insufficient tightness may point to erosion damage or otherdamage or misalignment at the valve seat or in other valve components.

By way of example, at step 1310 VAMS 700 may determine turbine and valveoperating parameters including rotor speed from the rotor speed sensor390 and steam pressures at various positions such as upstream of thestop valve 270, downstream of the control valve 280, and therebetweenfrom the pressure sensors 480, 490, 560. At step 1320, the stop valve270 may be open and the control valve 280 may be closed. At step 1330,rotor acceleration and rotor speed may be determined so as to provide anindication for the condition of the control valve seat. In a second modeof operating at step 1335, the stop valve 270 may close and the controlvalve 280 may open. At step 1338, rotor acceleration and rotor speed maybe determined, giving an indication for the condition of the stop valveseat. In a third mode of operation at step 1340, the stop valve 270 maybe opened and the control valve 280 may be closed. The stop valve 270then may be closed at step 1350. At step 1360, the pressure decaybetween the stop valve 270 and the control valve 280 may be determined,e.g., measured with the middle pressure sensor 575. At step 1370, astable pressure value may be determined once the pressure between thestop valve 270 and the control valve 280 has reached a stable value. Atstep 1380, VAMS 700 compares the rotor acceleration and/or the rotorspeed measured above to allowable values. Likewise, or in thealternative at step 1390, VAMS 700 may compare the determined pressuredecay (e.g., via the time constant or the difference of pressure in thebeginning and after some time) and/or the determined stable value ofpressure to allowable values. At step 1395, the determined rotoracceleration, the determined rotor speed, the determined pressure decay,and/or the determined stable value of pressure may be compared withmeasurements from previous tests and the trendline for each type ofmeasurement may be analyzed. If the trendlines show an increase largerthan an allowable increase or if the trendlines show that themeasurements come close to the allowable limits, then VAMS 700 mayprovide a leakage warning. Such a leakage warning may include not onlydisplaying the information to the operator but also taking the valve offline, changing one or more of the operating parameter or operatingconditions, and/or initiating repair procedures. The operatingparameters may include speed, pressure, temperature, spindle position,and the like. Specifically, if the allowed values are exceeded, valveerosion may have occurred and the valve components may need to bereplaced now, at the next inspection, or otherwise.

The Advanced Tightness Test Module 1300 may be done automatically ateach turbine start or on demand. The plant operator may consider thisinformation for inspection planning and to prepare spare parts inadvance. The Advanced Tightness Test Module 1300 thus gives the plantoperator a more accurate description of valve tightness without the needfor visual inspection and downtime.

FIG. 12 is a flow chart of exemplary method steps in a Spindle VibrationEvaluation Module 1400 as may be described herein. The Spindle VibrationEvaluation Module 1400 may observe and evaluate the nature of thevibrations of the valve spindles. Such vibration may cause wear of thespindles and the related guide bushes and damage therein.

By way of example at step 1410, VAMS 700 may determine turbine and valveoperating parameters including valve spindle position from the positionsensor 590, spindle vibration levels from the vibration sensor 580, andsteam pressure upstream and downstream of the valve from the pressuresensors 480, 490, 560, 575. At step 1420, the wear on the spindle andthe guide bushes may be assessed mainly from the vibration sensor 580,i.e., evaluating the vibration characteristics (e.g., frequency andamplitude or frequency and vibration velocity) and the duration of thevibrations. At step, 1430, the vibration and the duration may becompared to predetermined values. Based upon this assessment, the plantoperator may determine if replacement of the spindle or the guide bushesmay be required, for example, at the next planned outage. In additionand/or alternatively, the plant operator may change the overall steamturbine mode of operation so as to reduce the level of vibration at step1440. For example, one valve may be open slightly more and one valve maybe open slightly less. VAMS 700 also may take the valve out of serviceand/or initiate repair procedures.

The Spindle Vibration Evaluation Module 1400 thus gives the plantoperator an overview on the vibration behavior of the valve and theability to change the operating parameters back into a safe zone. Theoperator thus can prepare for planned inspections and order spare partsin advance. Moreover, the relationship between steam pressure, spindleposition, and vibration level may be recorded and provided to the plantoperator and/or valve designer. The Spindle Vibration Evaluation Module1400 thus may provide a more accurate description of vibration behaviorwithout the need for visual inspection and downtime.

FIG. 13 is a flow chart showing example method steps in an InsulationQuality Indicator Module 1500 as may be described herein. The InsulationQuality Indicator Module 1500 performs, preferably automatically andpermanently or on request, temperature measurements and evaluates,preferably automatically and permanently or on request, theeffectiveness of the valve insulation 315. For example, whether theinsulation 315 is ineffective due to aging or improper reassembly afteran inspection of the valve casing.

By way of example at step 1510, VAMS 700 may determine turbine and valveoperating parameters including inside and outside casing and insulationtemperatures from the inner and outer casing temperature sensors 520,530, 540, 550, and/or from dedicated insulation sensors. Specifically,temperatures may be determined at the metal surface of the casing,inside the insulation, at the surface of the insulation, and/or at thesurface of metal sheets outside the insulation. A double measurementwithin the casing wall thickness also may determine a temperaturegradient through the casing wall. Similar temperature gradients throughthe insulation also may be determined. Thermographic sensors and thelike also may be used to produce a thermographic picture of the wholeinsulated valve or of parts of the insulation surface. At step 1520,VAMS 700 may determine the effectiveness of the insulation. A lesseffective insulation may be shown by a higher temperature at theinsulation outer surface, a lower temperature at the outer surface ofthe casing wall, a higher temperature gradient through the casing wall,and/or a lower temperature gradient through the insulation thickness. Atstep 1530, VAMS 700 may provide an insulation warning if it isdetermined that the insulation is ineffective. Such an insulationwarning may include not only displaying the information to the operatorbut also taking the valve off line or changing one or more of theoperating parameter or operating conditions. The plant operator then maycorrect the insulation, order spare parts, and/or plan inspections.

The Insulation Quality Indicator Module 1500 thus gives the plantoperator a more accurate overview of the condition of the valves andturbine. The Insulation Quality Indicator Module 1500 provides anindication of whether the insulation is effective as intended. If not, awarning may be provided that the insulation is no longer effective dueto wrong assembly, aging, and the like. The Insulation Quality IndicatorModule 1500 thus may provide a more accurate description of valveinsulation without the need for visual inspection and downtime.

FIG. 14 is a flow chart showing exemplary method steps in a SolidParticle Erosion Indicator Module 1600 as may be described herein. TheSolid Particular Erosion Indicator Module 1600 evaluates the temperatureof the boiler pipeline and nature of the pipeline material so as toassess the risk of scaling therein. Temperature transients and steamvelocities in the boiler pipeline may influence when the scaling isdetaching from the boiler pipes and flowing with the steam into thevalve. The steam chemistry also may influence how fast scaling is buildup in the pipe lines. Scaling may lead to erosion of the valve and othertypes of turbine components, especially when the valve is throttling andhigh local steam velocities may occur, e.g., at the diffuser seat andthe valve bell or valve head.

By way of example in step 1610, VAMS 700 may determine turbine and valveoperating parameters including incoming steam temperatures from theboiler 160 in the high pressure line 180 via the high pressure inlettemperature sensor 420, 450 and including steam temperatures from thereheater 200 in the intermediate pressure line 210 via the intermediatepressure inlet temperature sensors 410, 460. Metal temperature sensorsat the pipe wall also may be used. At step 1620, VAMS 700 may look up ordetermine the nature of the steam chemistry of the incoming steam flowor of the condensing water in the steam/water cycle of the power plant.At step 430, VAMS 700 may look up or determine the throttling history ofthe valve in question. By way of example, the throttling history may bedetermined by the Advanced Throttling Time Counter Module 900 describedabove. Other types of counters and the like also may be used herein. Atstep 1640, VAMS 700 may look up the type of boiler piping material usedon the high pressure line 180 or elsewhere. At step 1650, VAMS 700 maydetermine the probability of solid particle erosion of the valvecomponents based upon the steam temperature and its transient, the steamchemistry, the throttling history, the boiler piping material, and thelike. The probability also may be evaluated on the timely coincidence ofmeasurements, e.g., when throttling occurs and at the same time a strongtemperature gradient is present, leading to a high flow of solidparticles from the boiler pipe and at the same time to high local speedsin the valve internals and therefore a high damaging effect. Theprobability of erosion damage may be accumulated over the time. At step1660, VAMS 700 may compare the current probability and/or accumulatedprobability with allowable values. Depending upon the nature of theprobability, VAMS, 700 may take the valve off line or changing one ormore of the operating parameter or operating conditions. The plantoperator then may order spare parts and/or plan inspections. The solidparticle erosion indicator module 1600 is also useful as one of severalmodules of an inspection interval counter.

The Solid Particle Erosion Indicator Module 1600 thus gives the plantoperator a more accurate overview of the condition of the valve partswith respect to erosion. The VAMS 700 may perform this evaluationautomatically. The Solid Particle Erosion Indicator Module 1600 thus mayprovide a more accurate description of possible erosion damage withoutthe need for visual inspection and downtime.

FIG. 15 is a flow chart showing exemplary method steps in a ScalingIndicator Module 1700 as may be described herein. The Scaling IndicatorModule 1700 may assess the scaling of the valve and other turbinecomponents based on temperature measurements, steam chemistry, andmaterial type. The Scaling Indicator Module 1700 may provide a predictedscaling status.

By way of example at step 1710, VAMS 700 may determine turbine and valveoperating parameters including steam temperatures from the various steamtemperature sensors 420, 430, 440, 450, 460 and metal temperatures fromthe metal temperature sensors 400, 410 preferably over the whole valveoperation time. At step 1720, VAMS 700 may determine or look up thesteam chemistry of the flow of steam preferably over the whole valveoperation time. At step 1730, VAMS 700 may determine the overall turbineoperation time. At step 1740, VAMS 700 may look up the nature of thematerials involved in the various valve components. At step 1750, VAMS700 may determine a scaling value for each valve component based on thetemperature history, steam chemistry history, and the nature of thematerial of each valve component. At step 1760, VAMS 700 may provide anoverall valve scaling indicator based on the nature of the mainmaterials in the valve. Specifically, VAMS 700 may provide a predictionof the condition of the various valve components based upon actualoperation time with respect to scaling. Depending upon the nature of therisk, VAMS 700 may take the valve off line or changing one or more ofthe operating parameter or operating conditions. The plant operator thenmay order spare parts and/or plan inspections.

The Scaling Indicator Module 1600 thus gives the plant operator a moreaccurate overview of the condition of the valve parts with respect toscaling of the valve components. The Scaling Indicator Module 1600provides a prediction as to when parts should be replaced. Based uponthese results, the plant operator may better prepare for plantinspections and or spare parts. The Scaling Indicator Module 1600 thusmay provide a more accurate description of possible valve scaling damagewithout the need for visual inspection and downtime.

FIG. 16 shows a flow chart of exemplary method steps in a FlexibleService Interval Counter Module 1800 as may be described herein. TheFlexible Service Interval Counter Module 1800 may determine if theinspection intervals should be expanded or shortened based on theoverall operation of the valve.

By way of example at step 1810, VAMS 700 may determine turbine and valveoperating parameters including steam pressure from the pressure sensors470, 480, 490, 560, 575, steam temperatures from the temperature sensors420, 430, 440, 450, 460, metal temperatures from the metal temperaturesensors 400, 410, 520, 530, 540, 550, the position of the spindle asdetermined by the position sensor 590, the hydraulic pressure in theactuator as determined by the hydraulic pressure sensor 595, the turbinespeed determined by the speed sensor 390, and the steam chemistry. Atstep 1820, VAMS 700 may compare the actual steam pressures to designsteam pressures. At step 1830, VAMS 700 may compare the actual steamtemperatures to design steam temperatures. At step 1840, VAMS 700 maycompare the actual metal temperatures to design metal temperatures. Atstep 1850, VAMS 700 may determine the valve vibration state. By way ofexample, the Advanced Throttling Time Counter Module 900 may be used todetermine the vibration state. Other types of analysis may be used. Atstep 1860, the valve friction state may be determined. By way ofexample, the Guide Condition Assessment Module 1000 may be used toherein. Other types of analysis may be used. At step 1870, the valvethrottling history may be determined. At step 1880, the number and kindof starts may be determined. By way of example, the advanced StartCounter Module 800 may be used herein. Other types of analysis may beused. At step 1890, VAMS 700 may consider each of these valveoperational parameters and the evaluated damage indicators to recommendthat the inspection interval be extended or shortened and/or if thevalve should be taken off line.

Specifically, the Advanced Throttling Time Counter Module 900 gives tothe plant operator the residual operation time until an inspection isrecommended. For example, when the valve is operated all the time atrelatively low temperature and pressure, then the recommended inspectioninterval, i.e., the operation time in between two inspections, may beextended as compared to the standard interval, whereas when the valve isoperated all the time at relatively high temperature and pressure, thenthe recommended inspection interval may be reduced as compared to thestandard value. High erosion probability, as detected by the erosionindicator, may reduce the recommended inspection interval. High detectedleakage through the valve seat, as measured and evaluated with theTightness Test Indicator or the Advanced Tightness Test Indicator, mayreduce the recommended inspection interval. High creep damage asdetected by a creep damage indicator may reduce the recommendedinspection interval. Relatively long throttling times, especially whenthe stroke position is in a critical area concerning vibrations, ase.g., detected by the Advanced Throttling Time Counter, may reduce therecommended inspection interval. High vibrations over longer time asevaluated with the Spindle Vibration Evaluation module may reduce therecommended inspection interval. Unfavorable steam chemistry, measuredover a longer time, may reduce the recommended inspection interval. Highscaling as detected by the Scaling Indicator Module may reduce therecommended inspection interval.

The Flexible Service Interval Counter Module 1800 thus provides theplant operator a recommendation on the time point of the nextinspection. This recommendation is based on the nature of the operationof the turbine and other influences. This inspection may be performedautomatically. Specifically, the inspection interval may be extendedwhen the valve is operating smoothly at low engine conditions.Inspection intervals may be shortened if any of the operationalparameters exceed allowed values. The Flexible Service Interval CounterModule 1800 thus may provide a more accurate description of valveconditions without the need for visual inspection and downtime.

VAMS 700 thus provides a permanent on-line valve and actuator monitoringproduct for steam turbines. Condition monitoring of the steam valves 260provides vital information on the health of the valves and the steamturbine system 100 as a whole. The monitored information may allow theoperator to make decisions to ensure optimal machine performance as wellas provide early warning of possible failures by detecting differentvalve failure symptoms at an early stage. VAMS 700 provides the operatorwith assessment reports suggesting measures to reduce outage costs andtime, modify operating conditions to reduce lifetime consumption, andtransitions from time based maintenance to condition based maintenanceto extend overall maintenance intervals.

It should be apparent that the foregoing relates only to certainembodiments of the present application and the resultant patent.Numerous changes and modifications may be made herein by one of ordinaryskill in the art without departing from the general spirit and scope ofthe invention as defined by the following claims and the equivalentsthereof.

I claim:
 1. A method of evaluating valve conditions in a turbine by adata acquisition system, comprising: receiving a plurality of operatingparameters from a plurality of sensors; wherein the plurality ofoperating parameters comprises steam temperatures determined over timeand steam pressure; determining a steam chemistry; determining athrottling history; looking up a piping material; calculating aprobability of valve erosion based upon the steam temperaturesdetermined over time, the steam chemistry, the throttling history, andthe piping material; and causing the turbine to implement a change toone or more of the plurality of operating parameters based upon thedetermined probability.
 2. The method of claim 1, wherein the step ofcausing the turbine to implement a change to one or more of theplurality of operating parameters comprises taking a valve out ofservice.
 3. The method of claim 1, wherein the step of causing theturbine to implement a change to one or more of the plurality ofoperating parameters comprises ordering parts.
 4. The method of claim 1,wherein the step of determining a steam chemistry comprises evaluating acondensing water flow.
 5. The method of claim 1, wherein the step ofdetermining a throttling history comprises a position of a valve spindleand valve pressure ratio.
 6. The method of claim 1, further comprisinginitiating repair procedures based upon the determined probability.
 7. Aturbine system, comprising: a plurality of valves; a plurality ofsensors capable of receiving turbine and valve operating parameters; anda data acquisition system, including a processor in communication withthe plurality of sensors and wherein the data acquisition system isoperable to perform the following operations: receiving the plurality ofturbine and valve operating parameters from the plurality of sensors;wherein the plurality of turbine and valve operating parameterscomprises steam temperatures determined over time; determining a steamchemistry and a throttling history; looking up a piping material; anddetermining a probability of valve erosion based upon the steamtemperatures, the steam chemistry, the throttling history, and thepiping material; and causing the turbine to implement a change to one ormore of the plurality of operating parameters based upon the determinedprobability.
 8. The turbine system of claim 7, wherein the dataacquisition system is further operable take a valve out of serviceand/or initiate repair procedures.
 9. The turbine system of claim 7,wherein the data acquisition system is further operable to alter one ormore of the plurality of operating parameters.
 10. The turbine system ofclaim 7, wherein the data acquisition system is further operable toorder parts.
 11. The turbine system of claim 7, wherein the plurality ofvalves comprises one or more steam stop valves and one or more steamcontrol valves.
 12. A method of evaluating valve conditions in a turbineby a data acquisition system, comprising: receiving, by the dataacquisition system, a plurality of operating parameters from a pluralityof sensors; wherein the plurality of operating parameters comprises asteam temperature and a time of operation; looking up, by the dataacquisition system, a steam chemistry; looking up, by the dataacquisition system, a piping material; determining, by the dataacquisition system, a probability of valve scaling based upon the steamtemperature, the time of operation, the steam chemistry, and the pipingmaterial; and causing, by the data acquisition system, the turbine toalter one or more of the plurality of operating parameters based uponthe determined probability.
 13. The method of claim 12, wherein the stepof causing the turbine to alter one or more of the plurality ofoperating parameters comprises taking a valve out of service.
 14. Themethod of claim 12, wherein the step of causing the turbine to alter oneor more of the plurality of operating parameters comprises orderingparts.